Effective well integrity practices ensure the protection of people, facilities and the environment from the risk of uncontrolled release of formation fluids throughout the life cycle of a well, so petroleum engineers are always required to ensure well integrity. Part of well integrity is to make sure downhole equipment and barriers are in excellent condition. Identifying the downhole leak source of pressure communication between tubingcasing and casing-casing annuli in any well is a huge challenge for petroleum engineers. Detecting any leak at the early stage is an important key to well integrity management. Two objectives were set in this paper as follows: The first objective is to develop a method that can detect downhole leaks by utilizing only rigless data based on full interpretation and evaluation of different logs in the field: temperature, noise, and corrosion log in different scenarios. The first scenario is shut-in condition while the second scenario is in flowing condition. The flowing condition will be either after bleeding off Tubing-Casing-Annulus or Casing-Casing-Annulus. This approach was implemented in a specific operation order to ensure job success. Also, the corrosion log was run to evaluate the condition of tubing and casing separately. The second objective of this study is to compare rigless approach results with the conventional rig approach for downhole leak detection, which will be completed by statistically analyzing corrosion, temperature, and noise surveys. Moreover, guidelines were set in each step of these surveys to confirm leak occurrence. This objective was achieved through developing a method and program for leak detection. Based on the conducted temperature, noise, and corrosion surveys, the integrated approach identified the leakage zones through the developed module in this report. The obtained results from the rigless approach were almost similar to the rig approach. The only difference between both approaches is that the developed method is more accurate, compared to the rig approach, since it can identify any corrosion or leak depth, while the rig approach will identify only leak zones. The paper will discuss in details the development of this method and its successful implementation in a few selected offshore wells in the same field of the Arabian Gulf.
One of the most serious oilfield problems is scale deposition, particularly when two incompatible waters are involved. The control of scale deposition in high-pressure/high-temperature (HP/HT) wells has been challenging because most scale inhibitors lose effectiveness at high temperatures as a result of molecular instability. Hence, in the context of adapting to the continuous challenges of the oil and gas industry, along with the need to preserve freshwater resources in the Middle East, an in-depth study of the scaling results of mixing fracturing fluid developed using nanofiltered (NF) seawater with formation water containing high total dissolved solids (TDS) under HP/HT conditions is discussed. A series of dynamic experiments was performed using a DSR-6000 dynamic scale loop at 330°F and 3,000 psi. Additionally, static experiments were conducted at room temperature and 330°F for 2 and 24 hours, respectively. For both dynamic and static tests, two mixing ratios were tested: 80:20 and 50:50 mixtures of NF seawater:formation brine. The 80:20 mixing ratio represents the worst-case scenario according to scale advisor software results. Moreover, regained core permeability at 300 and 330°F and retained proppant pack conductivity tests were also performed. Results demonstrated that, for dynamic scale loop testing, the lowest concentration of scale inhibitor tested (250 ppm) achieved the passing criteria along with all higher concentrations for both mixing ratios. The static tests were also successful, with no precipitation formed. Regained core permeability was in the range of 77 to 89%. Finally, retained proppant pack conductivity result of 56% indicated good cleanup properties for NF seawater.
Petroleum engineers are routinely required to estimate the production behavior of individual oil wells. Having an idea of the pressure-rate behavior enables engineers to evaluate various operating scenarios to ascertain the optimum production scheme. This also facilitates understanding how to design and install surface and subsurface production equipment whenever necessary. Knowledge of pressure-rate behavior is necessary for designing and evaluating stimulation treatments, or any operation that might improve flow efficiency. Estimates of future performance are also required for forecasting and planning purposes. The actual production mechanism and reservoir flow regimes around the horizontal well are considered more complicated than those for the vertical wells. Some combination of both linear and radial flow actually exists in the horizontal well. In literature, several authors such as Bendakhlia and Aziz, Cheng, and Retnanto and Economides concluded that the shape of measured inflow performance relationships (IPRs) is similar to the estimated IPR by Vogel. This paper critically evaluates the following analytical equations: modified Vogel's equation, Cheng's equation, Bendakhlia and Aziz's equation, and Retnanto and Economides' equation. These existing models are used to estimate the inflow performance relationship of two-phase flow in horizontal wells. In addition, a new correlation is presented for two-phase flow in horizontal wells that has fewer errors and is better fitting compared to the other correlations in the literature mentioned above. After the filtration process, a total of 62 sets of downhole production data were used for 18 horizontal wells. This data was utilized to evaluate the current two-phase IPR correlation for horizontal well. The data is also used to develop a new correlation that has less errors comparing with existing correlations and shows better fitting. A new classification range of 1 5 < P I < 1 5 is used in this study. For PI < 15 it was observed that Cheng's then Bendakhlia and Aziz's equations were the best with an error of 12.9% and 13.3% respectively. The Retnanto and Economides equation did not fit with the used data, which has an error of 93%, while the proposed correlation was the best compared to others with an error of 11%. For PI > 15 the following was noticed: Vogel's then Bendakhlia and Aziz's equations were the best with errors of 26% and 30%, respectively. Retnanto and Economides equation did not fit with the used data, which has an error of 207%, while the proposed correlation shows the best compared to other equations with an error of 13%.
Injectivity of water disposal wells is decreasing with time as tar accumulates in the wellbore and/or within the vicinity of the wellbore. The tar deposit reduces and deteriorates the effective wellbore length in addition to increasing mechanical skin across the sand face. The injectivity of water disposal wells can be effectively enhanced/stimulated by doing special chemical treatment mainly for sand stone reservoir. This helps to reduce injection bottom-hole pressure and consequently increase the pumping rates. This proposed chemical treatment was used for the first time in Saudi Arabia for sandstone reservoir to remove tar accumulation. The chemical treatment fluid (recipe) was tested in the lab and showed promising results. In this trial test, a water disposal well candidate with a low injection rate was selected to be implemented for the trial test. The treatment was aimed at enhancing well injectivity and the initial results of the field implementation demonstrate a significant improvement in the injection rate. This result was confirmed from the rate measurement before and after the treatment in addition to well testing analysis. Key results were consolidated with fall-off tests conducted before and after the treatment proving the effectiveness of the chemical treatment at reducing the skin and increasing the injection rate. In addition, this chemical is cost effective compared to other chemicals previously used for the same treatment objective. This paper also illustrates the current procedures and provides recommendations for future job execution with new procedures and steps to improve results.
Well testing in offshore environments is critical, challenging and often costly in terms of operations and logistics. The means of periodic testing for monitoring well performance offshore is typically through the use of a test barge. Tide cycles, which often pose mobility problems for the test barge, typically affect testing efficiency. Reducing the duration of normal production test improves field operations because of the increase of the possible number of wells that can be tested. This paper illustrates the benefits of using instantaneous shut-in wellhead pressure (ISWHP) for generating a pressure rate (PQ) curve in an offshore field in Saudi Arabia. Test barge optimization is shown through the construction of PQ curve for a well with single test data. In theory at least two points are required to construct the PQ curve. Since a single test data is typically obtained because of rate test scheduling optimization, the ISWHP technique for constructing the PQ curve would be an appropriate approach to optimize testing requirements each month and to obtain the base potential of each well. With the ISWHP measurement technique/methodology, a unique rate test will be enough to construct the PQ curve instead of two or more rate test data. This methodology is based on the principle of pressure transient analysis to distinguish the type of flow regime. The use of the pressure derivative plot (log pressure vs. log time) from gauge data and history plot of time verses pressure from Supervisory Control and Data Acquisition (SCADA) helps to determine the start of ISWHP. Field and hypothetical examples are provided to explain the methodology. Instead of an average two days of typical test barge activity for well testing, the ISWHP technique allows the termination of a test within 10 minutes after recording a rate test, with a significant improvement in testing efficiency. The number of well tests per month has almost doubled from applying the method in the field. A field wide application of the ISWHP decreases the need to conduct several tests per well, resulting in accurate or rapid diagnosis for well-timed decisions to enhance the field's production offshore.
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